integrated resource plan and transmission discussion psat ... · recap on last psat meeting 10:10...

Integrated Resource

Plan and Transmission

Discussion

PSAT Meeting

October 17, 2019

siemens.com/paceglobal Restricted © Siemens AG 2019

Unrestricted © Siemens AG 2019

Siemens Energy Business Advisory

Agenda

Welcome / Safety brief 10:00 am

Recap on last PSAT Meeting 10:10 am

Memphis Load Forecast 10:25 am

Natural Gas Market Considerations for MLGW 10:45 am

Resource Options Updates 11:00 am

Initial LTCE Results 11:15 am

Transmission Discussion (Working lunch) 12:15 pm

Breakout Session 12:30 pm

Summary of Breakout & Next steps 1:30 pm

Meeting adjourn 2:00 pm

Recap on last PSAT Meeting



Recap on last PSAT Meeting

• PSAT members provided comments/suggestions on mainly two questions:

1. List of generation options:

• Group 1: research Nuclear (modular), and Hydroelectric w/ Mississippi River

• Group 2: research Hydro, Residential / Commercial, Geothermal, Microgrids

2. Prioritize the recommended scenarios:

3. PSAT members generally concurred the comprehensiveness of other options presented:

• Sensitivity, Stochastics, Transmission approaches

4. The highlighted scenarios are given priority in our LTCE runs.

Base

Case

High

Tech

High

Reg.

No

Inflation

Worst

Historical

Best

Historical

Climate

Crisis

MISO Op.

Change

Group 1 5 4-5 5 1 3 1 4-5 1

Group 2 4 4 4 5 2 2 4

Memphis Load Forecast



Energy and Peak Forecast Approach

Fit regression to ten years of historical and GDP data and develop forecast by applying forecasted independent variables to fitted model.

• Historically, load has generally been decreasing for 10 years during a period of weak economic growth.

• Included ten years of humidity and temperature data in regression analysis, and applied over 50 years of weather for forecast.

• Including customer counts and limiting analysis to five-year data series (fitting to more recent trends) did not perform as well.

Apply decrements based on Energy Efficiency and Distributed Solar Generation penetrations.

• Program history would suggest limited impacts, and uncertain support for such programs in the future.

• Little measured data on impacts or estimates of penetrations; need to apply targets.

Apply increment based on Electric Vehicle penetration

• Adoption is low in Tennessee compared to the country, and expected to be lower in Memphis than elsewhere in Tennessee.



Modified Approach Based on September 25 Conference Call

Forecast based on regression model showed continued load declines into future.

• Continuous declines in load were unlikely for the entire period of analysis through 2040.

• A trending analysis would substitute for the longer-term forecast, and the magnitude of it

would be a consensus decision between Siemens and MLGW.

Siemens requested additional detail on future program designs and support for energy

efficiency and distributed solar resources.

Electric vehicle forecasts could be incorporated into the load forecast.



Proposed Load Forecast Before EE/EV/DS Adjustments

Blue dotted line (2009-18) represents linear trend of historical average and peak load values

Green (2019-25) is based on Federal Reserve forecast of GDP growth in regression equation.

Red is flat (2026-30) but growing (2031-40) at 0.01% (TVA IRP assumption).



Load Adjustments from DER / EE / EV

Load adjustments to MLGW forecast have three components:

1. Electric Vehicles (EVs) add to load

2. Distributed Solar (DS) and DER in general reduces load

3. Energy Efficiency (EE) reduces load

Need to estimate incremental adjustment because existing resources/ gains are “baked into”

forecast.

EV penetration was modeled based on limited

market data.

• Penetration is fairly low in Tennessee compared to

country

• Siemens modeling suggests it will be lower still in

Memphis.

• The impacts are modest (little over 1% increase)



Load Adjustments from DER / EE / EV

DS programs will terminate (namely Green Power Providers) but a replacement will be

deployed to honor obligations under PURPA.

• Siemens modeled a standard inflow-outflow metering design based on a comparable city in

the Midwest, offering a $500 incentive for each KW up to 4 KW.

• Estimated impacts are conservative.

• These programs are projected to start by 2025.

EE program history is limited, but MLGW intends to support limited programs

• EE was modeled to begin in 2024, rise to 0.3% of annual consumption in 2026 and hold

steady.

• Higher levels will require additional funding.



Net Average Load Forecast

2020 2025 2030 2035 2040

System-MW 1,614.64 1,576.04 1,576.04 1,583.94 1,591.88

EV-MW 0.70 2.72 7.07 13.46 20.07

EE-MW 0.00 5.94 8.90 8.95 8.99

DS-MW - 0.01 0.02 2.47 7.84

Net System-MW 1,615.34 1,572.82 1,574.19 1,585.99 1,595.11

EV+EE+DS as % 0.0% -0.2% -0.1% 0.1% 0.2%



Net Peak Load Forecast

2020 2025 2030 2035 2040

System Peak - MW 3,004.17 2,967.52 2,967.52 2,982.39 2,997.33

EV-MW 1.24 4.85 12.61 23.99 35.79

EE-MW 0.00 5.94 8.90 8.95 8.99

DS-MW - 0.00 0.00 0.08 0.26

Net System Peak - MW 3,005.41 2,966.44 2,971.23 2,997.36 3,023.87

EV/EE/DS as % 0.0% 0.0% 0.1% 0.5% 0.9%

Net impact in Peak Load is fairly

small under the Base Case

Natural Gas Market Considerations for

MLGW



U.S. Natural Gas Supply Growth is Expected Primarily in the

Appalachian and Permian Basins

2020 2030 2040 2020-40

CAGR

Appalachia (Pennsylvania, West Virginia, Ohio) 33.8 43.5 45.3 1.4%

Permian Basin (West Texas, New Mexico) 13.6 19.3 20.6 2.0%

Arkla-East Texas (Arkansas, Louisiana, Texas) 13.2 12.0 9.9 -1.4%

MidContinent (Oklahoma) 12.7 13.1 13.0 0.1%

Rockies (Colorado, Wyoming) 8.2 7.4 6.7 -1.0%

TX Gulf Onshore (Eagle Ford) 6.4 7.7 8.5 1.4%

Rest-of-U.S. 9.1 9.3 8.8 -0.1%

Western Canada (Alberta, British Colombia) 17.9 21.0 23.4 1.3%

Mexico 2.4 2.2 2.1 -0.5%

Gas Production by Key Regions (Bcf/d)

• Appalachia continues to see low breakeven costs

due to high initial production from wells in “sweet

spot” core acreage areas.

• Permian Basin supply growth is driven by

associated gas, which allows gas to be produced

at zero or even negative breakeven costs.

0

5

10

15

20

25

30

35

40

45

50

20

11

20

13

20

15

20

17

20

19

20

21

20

23

20

25

20

27

20

29

20

31

20

33

20

35

20

37

20

39

Bcf/d

Gas Production by Key U.S. Basins

Appalachia Permian Basin Arkla-East Texas

Midcontinent Rockies TX Gulf Onshore

Historical Forecast



U.S. Natural Gas Demand is Driven by Exports in the Short-Term

and by Industrial and Power Gen Demand in the Long-Term

• LNG export facilities are included in the outlook

once FID is reached, including the most recent

additions comprising a “second wave” (Golden

Pass, Calcasieu Pass, and Sabine Pass T6).

• Exports to Mexico grow as pipelines and gas-fired

IPP projects are completed in Mexico.

• Industrial demand grows steadily over time.

• Power generation demand is sensitive to gas

prices and to competing forms of generation, but is

expected to rise to 2030 before tapering to 2040.

0

5

10

15

20

25

30

35

40

20

11

20

13

20

15

20

17

20

19

20

21

20

23

20

25

20

27

20

29

20

31

20

33

20

35

20

37

20

39

Bcf/d

U.S. Demand by Sector

Res Com Industrial

Electric Gen LNG Exports to Canada

Exports to Mexico

Historical Forecast



Henry Hub Is Expected to Stay Below $3 in the Short-Term,

Fundamentals Suggest Longer-Term Price Rises

Henry Hub Price History, Futures, and Siemens EBA Forecast Key U.S. Gas Market Drivers:

• In the short-term, supply outpaces demand,

particularly as Permian associated gas

reaches the Gulf Coast on new pipelines.

• Note: This price outlook begins with futures

then transitions to fundamentals.

• In the medium-term, LNG exports, pipeline

exports to Mexico, power generation, and

industrial consumption drive up U.S. gas

demand -- largely focused on the U.S. Gulf

Coast region.

• Longer-term, the fundamentals outlook

indicates seasonal prices will compare with

history but still average less than

$4/MMBtu (in constant dollars).

$0

$1

$2

$3

$4

$5

$6

$7

$8

Jan

-09

Ma

r-10

Ma

y-1

1

Jul-

12

Se

p-1

3

No

v-1

4

Jan

-16

Ma

r-17

Ma

y-1

8

Jul-

19

Se

p-2

0

No

v-2

1

Jan

-23

Ma

r-24

Ma

y-2

5

Jul-

26

Se

p-2

7

No

v-2

8

Jan

-30

Ma

r-31

Ma

y-3

2

Jul-

33

Se

p-3

4

No

v-3

5

Jan

-37

Ma

r-38

Ma

y-3

9

Jul-

40

Historical Futures EBA 2018$ EBA Nominal$

Historical Forecast



Potential Natural Gas Market Indices for MLGW Include

Gas Hubs on Texas Gas, Trunkline, and ANR Pipelines

Trunkline: Basis at the Trunkline Zone 1A hub in southwest Louisiana is

expected to be lowest of the three hubs (with the exception of 2021) and

thus the most favorable index point from the point of view of the

consumer. Basis is lower in part due to the 2.2 Bcf/d Permian Global

Access pipeline that will deliver gas directly into southwest Louisiana.

Texas Gas: Basis at the Texas Gas Zone 1 hub near Greenville, MS

rises from -0.17 to -0.12 (and eventually -0.10) as natural gas demand in

the U.S. Gulf Coast increases from exports and power generation.

ANR: Basis at the ANR Patterson LA hub remains slightly less

competitive (from the consumer point of view) compared to the other two

hubs due to its receipt points (drawing on declining offshore production)

as well as its positioning to provide supply to LNG export demand.

-0.20

-0.18

-0.16

-0.14

-0.12

-0.10

-0.08

-0.06

-0.04

-0.02

0.00

20

19

20

21

20

23

20

25

20

27

20

29

20

31

20

33

20

35

20

37

20

39

2018$/M

MB

tu

Basis to Henry Hub

Texas Gas, zone 1

ANR Patterson LA

Trunkline Zone 1A



Texas Gas

(5 existing gates)

Trunkline

(2 existing gates)

ANR

(1 existing gate)

Gas Pipelines in MLGW

Service Territory

Firm Transport Tariffs:

Trunkline:

Field Zone to Zone 1A

Reservation: $0.2422/Dth*

Usage: $0.0079/Dth

Fuel: 0.88%

Texas Gas: SL-1

Reservation: $0.1552/Dth**

Usage: $0.0355/Dth

Fuel: 0.86%

ANR:

FTS-3 SE to SE Southern

Reservation: $0.1441/Dth***

Usage: $0.0142/Dth

Fuel: 1.46%

* Add $0.02 for EFT

** Add $0.0814 for EFT

*** Add $0.0954 for 2 hr notice



Several Pipelines Are Planned to Deliver Permian Gas to the

U.S. Gulf Coast, though Not All May Be Built

Waha Hub

Whistler Pipeline

2.0 Bcf/d

Announced

In-Service: 2021

Gulf Coast Express

1.9 Bcf/d

Under Construction

In-Service: Oct-2019

Pecos Trail

2.0 Bcf/d

Announced

In-Service: Mid-2021

Permian Highway

2.0 Bcf/d

Reached FID


Permian-to-Katy

2.2 Bcf/d

Reached FID


Blue Bonnet

2.0 Bcf/d

Announced

In-Service: 2022

Permian Global Access

2.2 Bcf/d

Open Season: May 2019

In-Service: 2023

Resource Options Updates



Resources Options Recap



Small Modular Reactor Technology

Background

• Technology originally developed for naval/shipping purposes and is being adapted for utility-

scale generation; however, not yet demonstrated commercial viability in the US.

• SMRs, like conventional nuclear plants, are carbon-free resources

Design Differences

• Employ self-contained systems smaller than traditional nuclear reactors and thus capacity can

be scaled by adding modules

• Modularity permits greater load following capability than typical of conventional nuclear

power plants

• Modules from 10 to 300 MW compared to roughly 900 to 1,200 MW for conventional

nuclear reactors

• Most of SMR technology is manufactured off-site in a controlled factory setting

• May reduce construction cost and duration and risk of cost overruns while increasing quality

• Designs include safety improvements by using underground containment designs and passive

cooling systems

Commercialization

• NuScale Power LLC plans: SMR into commercial operation in Utah, a dozen 50-MW reactors

• Only company with an SMR design certification pending before the US NRC

• NRC reviewing two SMR pre-applications from BWXT mPower, Inc. and SMR Inventec, LLC.

• Estimated costs are high for initial modules, but expected to decline rapidly with experience

SMR All-In Capital Cost, 2018$/kW



Bellefonte Units 1 and 2 Background

Owned by TVA and located in Hollywood, Alabama.

Two partially built 1,256 MW pressurized water reactors and construction suspended since1988, after a

combined $6 billion investment.

Subsequent asset recovery efforts resulted in both Units 1 and 2 being approximately 55% and 35% complete

(mechanical - nuclear island only) respectively.

October 2013, former TVA Chairman Dennis Bottorff and financier Franklin L. Haney proposed to finish the

Bellefonte using private funds and federal tax credits, and in 2015 TVA determined that it would be unlikely to

need Bellefonte for the next 20 years.

May 2016 TVA decided to auction the site, on November 2016, TVA entered into a sales agreement with

Franklin Haney’s Nuclear Development LLC (ND) to sell the Bellefonte site and facilities for $111 million.

On Feb 2019: TVA halt the sale because ND does not have construction permit/operating license from the NRC.

On May 2019: Federal court rejects TVA move to cancel sale of Bellefonte to ND. Both Units are currently in

Deferred Plant Status.

May 2020: ND projected trial date.

The NRC has not previously transferred a deferred construction permit on a nuclear plant to a private individual

or a company that has not previously operated a nuclear plant.



Bellefonte Key Questions

What are the actual construction costs?

SNC-Lavalin estimated the Total completion cost projected to be about half of what is projected

for a similar size plant in Georgia. estimated completion costs

• Unit 1 ~ $3 billion

• Unit 2 ~ $10 billion (a few years later)

TVA estimated in 2013 (SEC-10k) these costs to be substantially higher and that it would take 7

to 10 years to complete:

• Unit 1 ~ $7.6 to 8.7 billion

• Unit 2 ~ $9 billion

TVA indicated that this 2013 estimate is likely to be low due to the changes in standards and the

need to overhaul now outdated technology.



Cost and Financing to Complete Bellefonte Units 1 and 2

Will there be adequate cost support? Reported additional cost support

The following has been proposed:

• Over $2 billion in production tax credits obtained from the IRS

• Negotiating for federal loan guarantees from the DOE to cover 80% of cost

• Remaining 20% of cost via equity contributions

ND claims they should be able to finish the reactors at a cost allowing him to deliver power as

much as $500 million a year cheaper.

The transfer of the power to MLGW, will require TVA to provide wheeling or the power to be

wheeled to MISO (this is ok under TVA practices) and then the same considerations discussed

later in this presentation will apply



Hydro Generation Technology Variants

Types Description

Reservoir

storage

Moderate to large storage capacity behind a dam, generation dependent upon stored volume and head

• Large Reservoir/ Dam - traditional large scale hydro based on damming river to build an impoundment

• Not considered environmentally friendly because of the significant land alterations, impacts on wildlife, etc.

• Little to no remaining potential in the lower 48

• Low-Head Hydro - similar to traditional large dam based hydro, except on smaller scale

• Lower head requirement, significant potential remains unexploited

Run of River

Hydro

No, or very little, storage capacity behind the dam/ “pondage” with storage for a few hours/ days

• Generation dependent on the timing and size of river flows and elevation drop of a river

• More common in hilly/ mountainous regions with fast moving rivers, often seasonal

Pumped

Storage Hydro

Moderate storage at top and bottom of elevations

• Allows off-peak electricity to pump water from a river or lower reservoir to a higher reservoir to allow its release during peak times

• Requires reasonable elevation difference between reservoirs

Hydrokinetic

Essentially a propeller generator anchored to the river floor over which water flows

• A few U.S. projects, the most notable is in the East River, high capital and operating costs have slowed development.

• February 2019 FERC study for a 70kW system in Alaska estimated levelized energy costs could exceed other local options by

$322/ MWh with a total system energy cost of $787/MWh

• June 2019 the U.S. DOE Advanced Research Projects Agency (ARPA) released an RFI seeking industry insight into this technology

Initial LTCE Results



Supply Options

Self Supply Strategies

• Self Build – On Hold

• Select and screen various resource self-build options with input from MLGW on the various types

of generation technologies, demand-side and energy efficiency, and other known available capacity

and energy alternatives.

• Self Build + MISO

• Select and screen any combination of self-build and MISO market transactions to maximize cost

savings to MLGW over the study period.

We present next the initial results of the Self Build + MISO.

− The Results are representative of an initial “unconstrained” optimization and provides

information on what constraints should be in place for a practical application.



LTCE Requirements

RPS (Renewable Portfolio Standard)

• The Memphis Area Climate Action Plan calls for decarbonizing the electric grid with renewable energy,

increasing the percentage of carbon-free energy in electricity supply from the baseline of 60% in 2020

to 75% by 2035 and 100% by 2050, focusing on renewable sources such as solar and wind.

CO2 Emissions

• Reduce emissions 21% by 2020, 54% by 2035, and 81% by 2050. We modeled annual emission

targets based off the slopes from the targets from 2020 to 2035 and from 2035 to 2050. We used the

2016 Business as Usual Emissions from the 2019 Memphis Area Climate Action Plan to baseline our

emission targets.

Reserve margin target

• We set a minimum installed capacity requirement of 15%, which is the same reserve margin that

Tennessee Valley Authority uses.



Results of the Long Term Capacity Expansion Plan (LTCE)

30

Incre

asin

g

Regula

tion

Year

Advanced 2x1 Combined

Cycle

Advanced Simple Cycle

Frame CT Solar

Missouri

Wind Total MW

2024 1900 343 3500 200 5943

2026 0 0 0 100 100

2029 0 0 0 100 100

2032 0 0 0 100 100

2034 0 0 0 100 100

2035 0 0 200 0 200

2037 0 0 0 100 100

Total 1900 343 3700 700 6643

The LTCE identified a Portfolio made of two large Combined Cycle plants, one Simple Cycle Gas

Turbine, Solar PV, 37 x 100 MW solar plants and 7 x 100 Wind Turbine plants.



The Portfolio is Made of Combined Cycle Plants, Simple Cycle Gas Turbines

Solar PV and Wind Turbine Generation.

The LTCE is installing almost everything it needs in the first year it can; 2024.

This seems to be “bound” by meeting the renewable target of 65% by 2024

We also see this situation with flat or declining load, combined either with aging generation

fleet that is to retire as soon as possible, or as in the case of MLGW, that there is no pre-

exiting generation and the optimization is free to install or purchase as required.

Another aspect to be noted is that the optimization is installing more generation than

required to attend MLGW load but this is compensated by sales into MISO; (Cost of Supply

= Total Fleet Cost + Purchases – Sales).

This rises various questions:

a. What are the practical limits of installations per year? Clearly less than what was

selected by the LTCE.

b. Can the RPS targets be relaxed to achieve a more realistic installation rates?

c. What are the limits on capital expenditure by MLGW, if any?

d. Is it a valid strategy to over install to sell into MISO and lower the supply costs?



LTCE Results - The Portfolio is Oversized for the MLGW Demand Alone

32

Incre

asin

g

Regula

tion

Under this LTCE, installed Capacity results in a reserve margin of

23%, increasing to 27%, which is much higher than 15% required.

The energy production is greater than the demand for all years,

resulting in net sales.

There is no energy not served or loss of load hours (LOLH)



LTCE Results - Market Transactions

33

Incre

asin

g

Regula

tion

Under this LTCE, MLGW exports excess energy into the

market.

The exports reach almost 70% of the internal MLGW demand

but drop over time as the combined cycle plants dispatch

less.

There are some smaller levels of import (less than 10% of the

MLGW demand), so there are net sales into the market

starting at close to 60% of MLGW demand and dropping to

40% by the end of the period.

The sales into MLGW however are flat as shown in the figure

to the left.



LTCE Results - Renewable / Carbon-Free Energy

34

Incre

asin

g

Regula

tion

The Memphis Area Climate Action Plan calls for

decarbonizing the electric grid with renewable energy,

increasing the percentage of carbon-free energy in

electricity supply from the baseline of 60% in 2020 to 75%

by 2035 and 100% by 2050, focusing on renewable

sources such as solar and wind. (Note: it’s not part of the

base case)

The portfolio meets this target when expressed renewable

energy divided as a percentage of MLGW total energy

load.

When expressed as a percentage of the total generation in

MLGW (including sales), the percentage is below the

target.

Is this okay, provided that the internal supply meets the

target?



CO2 Emissions (tons)

35

Incre

asin

g

Regula

tion

The Memphis Area Climate Action Plan calls for

reducing Memphis area’s stationary energy CO2

emissions by 21% by 2020; 54% by 2035; and 81% by

2050. Year 2016 is the baseline with 7,900,671 tCO2e.

The Generation Portfolio meets this target with a good

margin, due to the fact that the generation from the

Combined Cycles is dropping over time.

Other effluents (NOx) are also reduced.

Are the Emission Limits, driving down the production

from efficient low emission units?

Would be valid to see the exports in the context of the

overall MISO or the generation (e.g. coal) displaced?



LTCE Results - Portfolio Costs and NPV ($000)

36

Incre

asin

g

Regula

tion

Under this LTCE run, the net cost after market revenues are $623 million per year (real), increasing towards

the end of the period due to the reduction in dispatch of the thermal units.

This results on an average cost of generation of $ 45/MWh rising towards the end to $ 52/MWh



LTCE Results - Portfolio Costs and NPV ($000)

37

Incre

asin

g

Regula

tion

Under this LTCE run, the NPV of the total costs is $ 7.6 Billion, where we observed that the highest

contributor is the Fixed Costs (mostly investments in renewables), followed by fuel and Market Sales

represent 40% reduction in the total costs.

NPV @ 3.5% of Cost( $ Million)

Fixed Cost 6,601$ 89%

Fuel 2,944$ 39%

Variable O&M 533$ 7%

Emissions 369$ 5%

Total (before Mkt sales) 10,447$ 140%

Market Sales (2,990)$ -40%

Total (after Mkt sales) 7,457$ 100%

Transmission Discussion




39

Incre

asin

g

Regula

tion

Understanding from Siemens’ discussion with MISO:

• MLGW and Siemens had a conversation with MISO on the opportunity to join MISO

• It was identified that a physical connection to MISO is required to join as a MISO

Transmission Owner (TO)

− MISO does not have position on the capacity on the interconnection.

− Historically this interconnection should be sufficient for the “firm” imports required to reliably serve

the load.

− Total capacity of interconnection needs further investigation with TVA/MISO

− Cost of transmission mostly responsible by MLGW

− Small membership fee

A physical interconnection is not required to join as a “Load Serving” member but in this

case TVA would need to accept to provide “Wheeling”. (see next)




40

Incre

asin

g

Regula

tion

• Understanding from Siemens’ discussion with TVA that:

1. Physical connection is required for MLGW to join MISO

− Reliability needs to be as good if not stronger than present

− Detailed cost assessment is necessary

2. Three outcomes to be considered:

− Deal: TVA provides wheeling & MLGW makes up the balance of customer’s hole by Exit

fees & wheeling payments (can be controversial). Minimal connection to MISO needed

− No Deal: MLGW disconnects completely from TVA; more expensive for MLGW due to

lack of mutual support with TVA , TVA customers will see a rate increase and their system

not as reliable as it could be. Multiple duplicated facilities around MLGW system.

− Middle Ground: MLGW makes a stronger connection, pays some services to TVA for

parallel flows and support. TVA customers see reduced impact and both system increase

reliability. There would be market dispatch flows between MLGW & TVA.



Transmission Parallel Flows

41

Incre

asin

g

Regula

tion

• Under normal conditions, there are

power flowing from MISO to TVA

and back to MISO.

• These are parallel (loop) flows and

normal in operations.

• Examples:

o Dell (MISO) to Shelby -Cordova -

Freeport (TVA) to Horn Lake -

Twinkle Town (MISO) – Stronger if

generation near Freeport is out.

o West Memphis (MISO) to

Birmingham Steel – Freeport (TVA)

to Horn Lake (MISO)

Dell (MISO) Shelby (TVA)

Cordova (TVA)

Allen (TVA-MLGW)

W.Mem(MISO)

McAdams(MISO)

Wolf Creek(TVA)

Freeport (TVA)

Horn Lake (MISO) MISO 230 kV



Interconnection Opportunities

42

Incre

asin

g

Regula

tion

*Cost estimate is subject to refinement

Freeport Substation

MISO 230kV

Freeport

Substation

TVA Southhaven CC

TVA 500kV

MLGW 161kV Expansion • 500 MVA potential capacity

• Available space for new breakers

and transformer

• Estimated cost $8 m*.




43

• Allen Option 1:

Purchase 8 miles Allen to TVA-

Entergy Intertie161 kV line from TVA

to create Allen (MLGW) to Horn Lake

(MISO) connection or build new 8

miles line above (200~500 MVA

potential capacity, est. cost $5~11 m*)

• Allen Option 2:

Build ~4.5 miles 500 kV line from

West Memphis to Allen (include MS

river crossing and new transformer)

(1700 MVA potential capacity, est.

total cost $ 45 m*)

4.5 miles 500 kV





Shelby 500 kV Options

• Purchase ~12 miles 500 kV line from TVA-

MISO intertie to Shelby and two 500/161 kV

transformers from TVA, ~2500 MVA capacity,

est. cost $30~35 m*.

• Build new ~12 mile 500 kV above including

river crossing and two new 500/161 kV

transformers, new substation, ~2500 MVA

capacity, est. cost $90 m*.

~12 miles

500kV


Breakout Session



Breakout Session

46

Incre

asin

g

Regula

tion

Demand Forecast Topics

1. Our Base Load Forecast (before EE and Distributed Resources) shows a flat to very slightly

increasing load over the long term. Is this consistent with PSAT expectations? If not how would you

see the load to evolve?

2. EV forecasts and electrification in general show a very modest levels of adoption. What are the

PSAT views on this? Are the base forecast too conservative?

3. EE programs require objectives / mandates and funding. What is the PSAT opinion on effective

programs for EE, levels of reduction?

4. What are the views on levels of rooftop solar? Our forecast again is showing very low impact. Note

that this is different than community solar which can be utility scale.



Breakout Session

47

Incre

asin

g

Regula

tion

Gas Topics / Supply Topics

1. Gas forecast identify the possibility of developing large combined cycle plants within the MLGW territory possibly

towards the east. Provided that issues related to water use are addressed, does the PSAT have views or concerns of

developing these plants in this area?

2. Small Modular Reactors (SMR) were investigated as well as hydro kinetic. It seems that SMR could become feasible in

the future, but it is unlikely to be selected. Same with hydro. Would the PSAT have concerns if these options are

dropped?

3. What are the main concerns about the Bellefonte option in the PSAT opinion?

Long Term Capacity Expansion Topics

1. The plan without constraints is installing most of the new generation in the first year. Does the PSAT agrees that we

need to define practical limits? Can the RPS targets be relaxed to achieve a more realistic installation rates?

2. Should there be limits on capital expenditure by MLGW, even if this drives higher long term costs?

3. Is it a valid strategy to over install to sell into MISO and offset the supply costs?



Breakout Session

48

Incre

asin

g

Regula

tion

Long Term Capacity Expansion Topics

1. Does a new generation mix largely driven by combined cycle units, PV and wind be within the

expectations of the PSAT? Is there something missing that should be added as “hard wired”,

storage?

2. Would it be acceptable to have a total generating fleet where the ratio of total renewable energy to

total energy produced is less than the RPS, provided that the ratio of renewable to load is at or

above the RPS?

3. How should the CO2 limits be applied? Does this apply to energy that is produced internally but sold

into MISO market?

Glossary



Glossary

• All-in Capital Cost = The capital costs for building a facility within the plant boundary, which includes equipment, installation labor, owners costs, allowance for funds used

during construction, and interest during construction.

• Appalachia Basin = Marcellus Shale Play and Utica Shale Play.

• Average Demand = Average of the monthly demand in megawatts.

• Average Heat Rate = The amount of energy used by an electrical generator to generate one kilowatt hour (kWh) of electricity.

• Baseload Heat Rate = The amount of energy used by an electrical generator to generate one kilowatt hour (kWh) of electricity at baseload production. Baseload production

is the production of a plant at an agreed level of standard environmental conditions.

• Breakeven Cost = Average price of gas required to cover capital spending (ideally adjusted to regional prices).

• BTU = British Thermal Unit = unit of energy used tipicaly for fuels.

• CF = Capacity Factor. The output of a power generating asset divided by the maximum capacity of that asset.

• CC = Combined Cycle

• EE = Energy Efficiency

• CCS = Carbon Capture and Sequestration

• CT = Combustion Turbine

• DER = Distributed Energy Resources, distributed generation, small scale decentralized power generation or storage technologies

• DS = Distributed Solar

• Dth = Dekatherm (equal to one million British Thermal Units or 1 MMBtu)

• EFT = Enhanced Firm Transportation (varies by pipeline but can include short- or no-notice changes to day-ahead nominations of fuel delivery

• FID = Final Investment Decision

• FOM = Fixed operations and maintenance costs

• FT = Firm Transportation. FT capacity on a natural gas pipeline is available 24/7 and is more expensive than interruptible transportation (IT) capacity but unused FT

capacity can be sold on secondary market.

• Futures = Highly standardized contract. Natural gas futures here are traded on the New York Mercantile Exchange (NYMEX) or Chicago Mercantile Exchange (CME).

• GT = Gas Turbine

• PPA = Power Purchase Agreement; contract to purchase the power from a generating asset

• IPP = Independent Power Producer

• IRP = Integrated Resource Plan



Glossary

• LNG = Liquified natural gas

• LOLE = loss of load expectation

• LOLH = loss of load hours,

• LTCE = Long Term Capacity Expansion Plan; optimization process to select generation.

• MMBTu = million British Thermal Units, unit of energy usually used for fuels.

• MWh = unit of energy usually electric power = 1 million watts x hour

• MW = unit of power = 1 million watts

• Peak Demand = The maximum demand in megawatts (MW) for a year.

• PV = Photovoltaic

• Reserve Margin = The amount of electric generating capacity divided by the peak demand.

• SMR = Small Modular Reactor

• “Sweet Spot” Core Acreage = Areas within a natural gas play that offer the highest production at least cost.

• Utility Scale = large grid-connected power generation, could be solar, gas, diesel, etc.

• VOM = Variable operations and maintenance costs

• Wheeling = a transaction by which a generator injects power onto a third party transmission system for delivery to a client (load).

integrated resource plan and transmission discussion psat ... · recap on last psat meeting 10:10...

Documents